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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________________ to _______________
Commission file number 33-47668-01
SOUTHWEST ROYALTIES INSTITUTIONAL 1992-93 INCOME PROGRAM
Southwest Royalties Institutional Income Fund XI-A, L.P.
(Exact name of registrant as specified
in its limited partnership agreement)
Delaware 75-2427297
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
407 N. Big Spring, Suite 300
_________Midland, Texas 79701_________
(Address of principal executive offices)
________(915) 686-9927________
(Registrant's telephone number,
including area code)
Indicate by check mark whether registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days:
Yes __X__ No _____
The total number of pages contained in this report is 19.
PART I. - FINANCIAL INFORMATION
Item 1. Financial Statements
The unaudited condensed financial statements included herein have been
prepared by the Registrant (herein also referred to as the "Partnership")
in accordance with generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q and Rule 10-01
of Regulation S-X. Accordingly, they do not include all of the information
and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, all
adjustments necessary for a fair presentation have been included and are of
a normal recurring nature. The financial statements should be read in
conjunction with the audited financial statements and the note thereto for
the year ended December 31, 1998 which are found in the Registrant's Form
10-K Report for 1998 filed with the Securities and Exchange Commission.
The December 31, 1998 balance sheet included herein has been taken from the
Registrant's 1998 Form 10-K Report. Operating results for the three and
nine month periods ended September 30, 1999 are not necessarily indicative
of the results that may be expected for the full year.
Southwest Royalties Institutional Income Fund XI-A, L.P.
Balance Sheets
September 30, December 31,
1999 1998
------------- ------------
(unaudited)
Assets
Current assets
Cash and cash equivalents $ 23,842 57,406
Receivable from Managing General Partner 44,907 30,869
-----------
-------
Total current assets 68,749 88,275
--------- ---------
Oil and gas properties - using the
full cost method of accounting 2,029,774 2,029,769
Less accumulated depreciation,
depletion and amortization 1,576,862 1,541,862
--------- ---------
Net oil and gas properties 452,912 487,907
--------- ---------
$ 521,661 576,182
========= =========
Liabilities and Partners' Equity
Partners' equity
General partners $ (25,734) (25,178)
Limited partners 547,395 601,360
--------- ---------
Total partners' equity 521,661 576,182
--------- ---------
$ 521,661 576,182
========= =========
Southwest Royalties Institutional Income Fund XI-A, L.P.
Statements of Operations
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
---- ---- ---- ----
Revenues
Income from net profits
interests $ 59,408 33,644 115,902 79,528
Interest 433 24 1,363 970
Miscellaneous income - 9,937 20,999 (45,159)
------ ------- ------- -------
59,841 43,605 138,264 35,339
------ ------- ------- -------
Expenses
General and administrative 9,563 13,151 32,825 46,691
Depreciation, depletion and
amortization 7,000 16,000 35,000 90,000
Provision for impairment of
oil and gas properties - - - 147,497
------ ------- ------- -------
16,563 29,151 67,825 284,188
------ ------- ------- -------
Net income (loss) $ 43,278 14,454 70,439 (248,849)
====== ======= ======= =======
Net income (loss) allocated to:
Managing General Partner $ 4,525 1,847 7,600 3,043
====== ======= ======= =======
General Partner $ 503 205 844 338
====== ======= ======= =======
Limited Partners $ 38,250 12,402 61,995 (252,230)
====== ======= ======= =======
Per limited partner unit $ 7.06 2.29 11.44 (46.55)
====== ======= ======= =======
Southwest Royalties Institutional Income Fund XI-A, L.P.
Statements of Cash Flows
(unaudited)
Nine Months Ended
September 30,
1999 1998
---- ----
Cash flows from operating activities
Cash received from income from net
profits interests $ 91,083 121,048
Cash paid to suppliers (1,045) (30,105)
Interest received 1,363 970
------- -------
Net cash provided by operating activities 91,401 91,913
------- -------
Cash flows provided by investing activities
Cash received from sale of oil and gas
property interest - 6,543
Addition of oil and gas properties (5) -
------- -------
Net cash provided by (used in) investing
activities (5) 6,543
------- -------
Cash flows used in financing activities
Distributions to partners (124,960) (140,904)
------- -------
Net decrease in cash and cash equivalents (33,564) (42,448)
Beginning of period 57,406 52,190
------- -------
End of period $ 23,842 9,742
======= =======
(continued)
Southwest Royalties Institutional Income Fund XI-A, L.P.
Statements of Cash Flows, continued
(unaudited)
Nine Months Ended
September 30,
1999 1998
---- ----
Reconciliation of net income (loss) to net
cash provided by operating activities
Net income (loss) $ 70,439 (248,849)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
Depreciation, depletion and amortization 35,000 90,000
Provision for impairment of oil and gas properties -
147,497
(Increase) decrease in receivables (24,819) 41,520
Increase in payables 10,781 61,745
------- -------
Net cash provided by operating activities $ 91,401 91,913
======= =======
Southwest Royalties Institutional Income Fund XI-A, L.P.
(a Delaware limited partnership)
Notes to Financial Statements
1. Organization
Southwest Royalties Institutional Income Fund XI-A, L.P. was organized
under the laws of the state of Delaware on May 5, 1992, for the
purpose of acquiring producing oil and gas properties and to produce
and market crude oil and natural gas produced from such properties for
a term of 50 years, unless terminated at an earlier date as provided
for in the Partnership Agreement. The Partnership will sell its oil
and gas production to a variety of purchasers with the prices it
receives being dependent upon the oil and gas economy. Southwest
Royalties, Inc. serves as the Managing General Partner and H. H.
Wommack, III, as the individual general partner. Partnership profits
and losses, as well as all items of income, gain, loss, deduction, or
credit, will be credited or charged as follows:
Limited General
Partners Partners (1)
-------- --------
Organization and offering expenses (2) 100% -
Acquisition costs 100% -
Operating costs 90% 10%
Administrative costs (3) 90% 10%
Direct costs 90% 10%
All other costs 90% 10%
Interest income earned on capital
contributions 100% -
Oil and gas revenues 90% 10%
Other revenues 90% 10%
Amortization 100% -
Depletion allowances 100% -
(1) H.H. Wommack, III, President of the Managing General
Partner, is an additional general partner in the Partnership and
has a one percent interest in the Partnership. Mr. Wommack is
the majority stockholder of the Managing General Partner whose
continued involvement in Partnership management is important to
its operations. Mr. Wommack, as a general partner, shares also
in Partnership liabilities.
(2) Organization and Offering Expenses (including all cost of
selling and organizing the offering) include a payment by the
Partnership of an amount equal to three percent (3%) of Capital
Contributions for reimbursement of such expenses. All
Organization Costs (which excludes sales commissions and fees) in
excess of three percent (3%) of Capital Contributions with
respect to a Partnership will be allocated to and paid by the
Managing General Partner.
(3) Administrative Costs will be paid from the Partnership's
revenues; however; Administrative Costs in the Partnership year
in excess of two percent (2%) of Capital Contributions shall be
allocated to and paid by the Managing General Partner.
Southwest Royalties Institutional Income Fund XI-A, L.P.
Note to Financial Statements
2. Summary of Significant Accounting Policies
The interim financial information as of September 30, 1999, and for
the three and nine months ended September 30, 1999, is unaudited.
Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted in this Form 10-Q
pursuant to the rules and regulations of the Securities and Exchange
Commission. However, in the opinion of management, these interim
financial statements include all the necessary adjustments to fairly
present the results of the interim periods and all such adjustments
are of a normal recurring nature. The interim consolidated financial
statements should be read in conjunction with the audited financial
statements for the year ended December 31, 1998.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Southwest Royalties Institutional Income Fund XI-A, L.P. (the Partnership)
was organized as a Delaware limited partnership on May 5, 1992. The
offering of such limited partnership interests began August 20, 1992, as
part of a shelf offering registered under the name Southwest Royalties
Institutional 1992-93 Income Program. Minimum capital requirements for the
Partnership were met on December 10, 1992 and the offering concluding on
April 30, 1993 with total limited partner contributions of $2,709,000.
The Partnership was formed to acquire royalty and net profits interests in
producing oil and gas properties, to produce and market crude oil and
natural gas produced from such properties, and to distribute the net
proceeds from operations to the limited and general partners. Net revenues
from producing oil and gas properties will not be reinvested in other
revenue producing assets except to the extent that production facilities
and wells are improved or reworked or where methods are employed to improve
or enable more efficient recovery of oil and gas reserves.
Increases or decreases in Partnership revenues and, therefore,
distributions to partners will depend primarily on changes in the prices
received for production, changes in volumes of production sold, lease
operating expenses, enhanced recovery projects, offset drilling activities
pursuant to farm-out arrangements, sales of properties, and the depletion
of wells. Since wells deplete over time, production can generally be
expected to decline from year to year.
Well operating costs and general and administrative costs usually decrease
with production declines; however, these costs may not decrease
proportionately. Net income available for distribution to the partners is
therefore expected to fluctuate in later years based on these factors.
Based on current conditions, management does not anticipate performing
workovers. The Partnership could possibly experience a steady decline.
Oil and Gas Properties
Oil and gas properties are accounted for at cost under the full-cost
method. Under this method, all productive and nonproductive costs incurred
in connection with the acquisition, exploration and development of oil and
gas reserves are capitalized. Gain or loss on the sale of oil and gas
properties is not recognized unless significant oil and gas reserves are
involved.
The Partnership's policy for depreciation, depletion and amortization of
oil and gas properties is computed under the units of revenue method.
Under the units of revenue method, depreciation, depletion and amortization
is computed on the basis of current gross revenues from production in
relation to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.
Should the net capitalized costs exceed the estimated present value of oil
and gas reserves, discounted at 10%, such excess costs would be charged to
current expense. For the quarter ended September 30, 1999, the net
capitalized costs did not exceed the estimated present value. A return to
the oil price environment experienced during the first two quarters of 1999
would have an adverse affect on the Company's revenues and operating cash
flow. Also, further declines in oil prices could result in additional
decreases in the carrying value of the Company's oil and gas properties.
Results of Operations
A. General Comparison of the Quarters Ended September 30, 1999 and 1998
The following table provides certain information regarding performance
factors for the quarters ended September 30, 1999 and 1998:
Three Months
Ended Percentage
September 30, Increase
1999 1998 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 21.71 11.31 92%
Average price per mcf of gas $ 2.33 1.97 18%
Oil production in barrels 2,060 3,600 (43%)
Gas production in mcf 27,860 32,900 (15%)
Income from net profits interests $ 59,408 33,644 77%
Partnership distributions $ 40,000 1,000 3,900%
Limited partner distributions $ 36,000 900 3,900%
Per unit distribution to limited partners $ 6.64 .17 3,900%
Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests increased to $59,408
from $33,644 for the quarters ended September 30, 1999 and 1998,
respectively, an increase of 77%. The principal factors affecting the
comparison of the quarters ended September 30, 1999 and 1998 are as
follows:
1. The average price for a barrel of oil received by the Partnership
increased during the quarter ended September 30, 1999 as compared to
the quarter ended September 30, 1998 by 92%, or $10.40 per barrel,
resulting in an increase of approximately $37,400 in income from net
profits interests. Oil sales represented 41% of total oil and gas
sales during the quarter ended September 30, 1999 as compared to 39%
during the quarter ended September 30, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 18%, or $.36 per mcf, resulting in
an increase of approximately $11,800 in income from net profits
interests.
The total increase in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$49,200. The market price for oil and gas has been extremely volatile
over the past decade, and management expects a certain amount of
volatility to continue in the foreseeable future.
2. Oil production decreased approximately 1,540 barrels or 43% during the
quarter ended September 30, 1999 as compared to the quarter ended
September 30, 1998, resulting in a decrease of approximately $33,400 in
income from net profits interests.
Gas production decreased approximately 5,040 mcf or 15% during the same
period, resulting in a decrease of approximately $11,700 in income from
net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $45,100. The decrease in
production was primarily due to property sales.
3. Lease operating costs and production taxes were 30% lower, or
approximately $21,800 less during the quarter ended September 30, 1999
as compared to the quarter ended September 30, 1998. The decline in
lease operating costs is primarily in relation to the drop in oil
prices experienced throughout 1998 and into the first six months of
1999, which made it uneconomical to perform workovers and major
repairs. Although prices have increased during the third quarter of
1999, only routine repairs and maintenance for the most part are being
performed.
Costs and Expenses
Total costs and expenses decreased to $16,563 from $29,151 for the quarters
ended September 30, 1999 and 1998, respectively, a decrease of 43%. The
decrease is the result of lower depletion expense and general and
administrative expense.
1. General and administrative costs consists of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased
27% or approximately $3,600 during the quarter ended September 30, 1999
as compared to the quarter ended September 30, 1998. The decrease of
general and administrative costs were in part due to additional
accounting costs incurred in 1998 in relation to the outsourcing of K-1
tax package preparation; a change in auditors requiring opinions from
both the predecessors and successor auditors and a new accounting
pronouncement requiring review by the independent auditors of the 10-
Q's. The Managing General Partner has also made an effort to cut back
on general and administrative costs whenever and wherever possible.
2. Depletion expense decreased to $7,000 for the quarter ended September
30, 1999 from $16,000 for the same period in 1998. This represents a
decrease of 56%. Depletion is calculated using the units of revenue
method of amortization based on a percentage of current period gross
revenues to total future gross oil and gas revenues, as estimated by
the Partnership's independent petroleum consultants. Contributing
factors to the decline in depletion expense between the comparative
periods were the increase in the price of oil and gas used to determine
the Partnership's reserves for October 1, 1999 as compared to 1998.
B. General Comparison of the Nine Month Periods Ended September 30, 1999
and 1998
The following table provides certain information regarding performance
factors for the nine month periods ended September 30, 1999 and 1998:
Nine Months
Ended Percentage
September 30, Increase
1999 1998 (Decrease)
---- ---- ---------
Average price per barrel of oil $ 14.82 11.64 27%
Average price per mcf of gas $ 2.05 1.86 10%
Oil production in barrels 6,530 10,800 (40%)
Gas production in mcf 79,660 97,400 (18%)
Income from net profits interests $ 115,902 79,528 46%
Partnership distributions $ 124,960 141,000 (11%)
Limited partner distributions $ 115,960 126,900 (9%)
Per unit distribution to limited partners $ 21.40 23.42 (9%)
Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests increased to $115,902
from $79,528 for the nine months ended September 30, 1999 and 1998,
respectively, an increase of 46%. The principal factors affecting the
comparison of the nine months ended September 30, 1999 and 1998 are as
follows:
1. The average price for a barrel of oil received by the Partnership
increased during the nine months ended September 30, 1999 as compared
to the nine months ended September 30, 1998 by 27%, or $3.18 per
barrel, resulting in an increase of approximately $34,300 in income
from net profits interests. Oil sales represented 37% of total oil and
gas sales during the nine months ended September 30, 1999 as compared
to 41% during the nine months ended September 30, 1998.
The average price for an mcf of gas received by the Partnership
increased during the same period by 10%, or $.19 per mcf, resulting in
an increase of approximately $18,500 in income from net profits
interests.
The total increase in income from net profits interests due to the
change in prices received from oil and gas production is approximately
$52,800. The market price for oil and gas has been extremely volatile
over the past decade, and management expects a certain amount of
volatility to continue in the foreseeable future.
2. Oil production decreased approximately 4,270 barrels or 40% during the
nine months ended September 30, 1999 as compared to the nine months
ended September 30, 1998, resulting in a decrease of approximately
$63,300 in income from net profits interests.
Gas production decreased approximately 17,740 mcf or 18% during the
same period, resulting in a decrease of approximately $36,400 in income
from net profits interests.
The total decrease in income from net profits interests due to the
change in production is approximately $99,700. The decrease in
production was due primarily to property sales.
3. Lease operating costs and production taxes were 37% lower, or
approximately $83,300 less during the nine months ended September 30,
1999 as compared to the nine months ended September 30, 1998. The
decline in lease operating costs is primarily in relation to the drop
in oil prices experienced throughout 1998 and into the first six months
of 1999, which made it uneconomical to perform workovers and major
repairs. Although prices have increased during the third quarter of
1999, only routine repairs and maintenance for the most part are being
performed.
Costs and Expenses
Total costs and expenses decreased to $67,825 from $284,188 for the nine
months ended September 30, 1999 and 1998, respectively, a decrease of 76%.
The decrease is the result of lower general and administrative expense and
depletion expense.
1. General and administrative costs consists of independent accounting and
engineering fees, computer services, postage, and Managing General
Partner personnel costs. General and administrative costs decreased
30% or approximately $13,900 during the nine months ended September 30,
1999 as compared to the nine months ended September 30, 1998. The
decrease of general and administrative costs were in part due to
additional accounting costs incurred in 1998 in relation to the
outsourcing of K-1 tax package preparation; a change in auditors
requiring opinions from both the predecessors and successor auditors
and a new accounting pronouncement requiring review by the independent
auditors of the 10-Q's. The Managing General Partner has also made an
effort to cut back on general and administrative costs whenever and
wherever possible.
2. Depletion expense decreased to $35,000 for the nine months ended
September 30, 1999 from $90,000 for the same period in 1998. This
represents a decrease of 61%. Depletion is calculated using the units
of revenue method of amortization based on a percentage of current
period gross revenues to total future gross oil and gas revenues, as
estimated by the Partnership's independent petroleum consultants.
Contributing factors to the decline in depletion expense between the
comparative periods were the increase in the price of oil and gas used
to determine the Partnership's reserves for October 1, 1999 as compared
to 1998.
3. The net capitalized costs for the nine months ended September 30, 1998
exceeded the estimated present value of oil and gas reserves,
discounted at 10% in the amount of $147,497, such excess costs were
charged to current expense. The write-down had the effect of reducing
net income, but did not affect cash flow or partner distributions.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from
interests in oil and gas properties. The Partnership knows of no material
change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $91,400 in
the nine months ended September 30, 1999 as compared to approximately
$91,900 in the nine months ended September 30, 1998. The primary source of
the 1999 cash flow from operating activities was profitable operations.
Cash flows (used in) or provided by investing activities were approximately
$(5) in the nine months ended September 30, 1999 as compared to
approximately $6,500 in the nine months ended September 30, 1998.
Cash flows used in financing activities were approximately $125,000 in the
nine months ended September 30, 1999 as compared to approximately $140,900
in the nine months ended September 30, 1998. The only use in financing
activities was the distributions to partners.
Total distributions during the nine months ended September 30, 1999 were
$124,960 of which $115,960 was distributed to the limited partners and
$9,000 to the general partners. The per unit distribution to limited
partners during the nine months ended September 30, 1999 was $21.40. Total
distributions during the nine months ended September 30, 1998 were $141,000
of which $126,900 was distributed to the limited partners and $14,100 to
the general partners. The per unit distribution to limited partners during
the nine months ended September 30, 1998 was $23.42.
The source for the 1999 distributions of $124,960 was oil and gas
operations of approximately $91,400 and the change in oil and gas
properties of approximately (5), with the balance from available cash on
hand at the beginning of the period. The sources for the 1998
distributions of $141,000 were oil and gas operations of approximately
$91,900, the change in oil and gas properties of approximately $6,500, with
the balance from available cash on hand at the beginning of the period.
Since inception of the Partnership, cumulative monthly cash distributions
of $1,659,408 have been made to the partners. As of September 30, 1999,
$1,519,158 or $280.39 per limited partner unit has been distributed to the
limited partners, representing a 56% return of the capital contributed.
As of September 30, 1999, the Partnership had approximately $68,700 in
working capital. The Managing General Partner knows of no unusual
contractual commitments and believes the revenues generated from operations
are adequate to meet the needs of the Partnership.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with
over $21.0 million of interest payments due within the next twelve months
on its debt obligations. Due to the severely depressed commodity prices
experienced for the past eighteen months, the Managing General Partner is
experiencing difficulty in generating sufficient cash flow to meet its
obligations and sustain its operations. The Managing General Partner is
currently in the process of renegotiating the terms of its various
obligations with its creditors and/or attempting to seek new lenders or
equity investors. Additionally, the Managing General Partner would
consider disposing of certain assets in order to meet its obligations.
There can be no assurance that the Managing General Partner's debt
restructuring efforts will be successful or that the lenders will agree to
a course of action consistent with the Managing General Partners
requirements in restructuring the obligations. Even if such agreement is
reached, it may require approval of additional lenders, which is not
assured. Furthermore, there can be no assurance that the sales of assets
can be successfully accomplished on terms acceptable to the Managing
General Partner. Under current circumstances, the Managing General
Partner's ability to continue as a going concern depends upon its ability
to (1) successfully restructure its obligations or obtain additional
financing as may be required, (2) maintain compliance with all debt
covenants, (3) generate sufficient cash flow to meet its obligations on a
timely basis, and (4) achieve satisfactory levels of future earnings. If
the Managing General Partner is unsuccessful in its efforts, it may be
unable to meet its obligations making it necessary to undertake such other
actions as may be appropriate to preserve asset values.
Information Systems for the Year 2000
The Managing General Partner provides all data processing needs of the
Partnership. The Managing General Partner has identified and assessed its
exposure to the potential Year 2000 software and imbedded chip processing
and date sensitivity issue. Through the Managing General Partners data
processing subsidiary, Midland Southwest Software, Inc., the Managing
General Partner proactively initiated an internal plan to identify
applicable hardware and software, assess impact and effect, estimate costs,
construct and implement corrective actions, and prepare contingency plans.
Identification & Assessment
The Managing General Partner currently believes it identified the internal
and external software and hardware that had the potential for date
sensitivity problems. Four critical systems and/or functions were
identified and addressed: (1) the proprietary software of the Partnership
(OGAS) that is used for oil & gas property management and financial
accounting functions, (2) the DEC VAX/VMS hardware and operating system,
(3) various third-party application software including lease economic
analysis, fixed asset management, geological applications, and
payroll/human resource programs, and (4) External Agents.
The proprietary software of the Partnership has met compliance
requirements. Since this is an internally generated software package, the
Managing General Partner incurred approximately $25,000 in man-hours.
Modifications were made by internal staff and did not represent additional
costs to the Partnership. The Managing General Partner has not made
contingency plans at this time since the conversion is ahead of schedule
and being handled by Managing General Partner controlled internal
programmers. Given the complexity of the systems that were modified, it is
anticipated that some problems may arise, but having met the early
completion date, the Managing General Partner feels that adequate time
remains available to overcome unforeseen delays.
DEC has released a fully compliant version of its operating system that is
used by the Partnership on the DEC VAX system. It was installed, the
Managing General Partner believes that this solved any potential problems
on the system.
The Managing General Partner has identified various third-party software
that may have date sensitivity problems and is continuing to work with the
vendors to secure solutions as well as prepare contingency plans. After
review and evaluation of the vendor plans and status, the Managing General
Partner believes that the problems will be resolved prior to the year 2000
or the alternate contingency plan will sufficiently and adequately
remediate the problem so that there is no material disruption to business
functions.
The External Agents of the Partnership include suppliers, customers,
owners, vendors, banks, product purchasers including pipelines, and other
oil and gas property operators. The Managing General Partner is in the
process of identifying and communicating with each critical External Agent
about its plan and progress thereof in addressing the Year 2000 issue.
This process is on schedule and the Managing General Partner, at this time,
believes that there should be no material interference or disruption
associated with any of the critical External Agent's functions necessary to
the Partnership's business. The Managing General Partner estimates
completion of this audit by year end 1999 and believes that alternate plans
can be devised to circumvent any material problems arising from critical
External Agent noncompliance.
Cost
To date, the Managing General Partner has incurred only minimal internal
man-hour costs for identification, planning, and maintenance. The Managing
General Partner believes that the necessary additional costs will also be
minimal and most will fall under normal and general maintenance procedures
and updates. An accurate cost cannot be determined at this time, but it is
expected that the total cost to remediate all systems to be less than
$50,000.
Risks/Contingency
The failure to correct critical systems of the Partnership, or the failure
of a material business partner or External Agent to resolve critical Year
2000 issues could have a serious adverse impact on the ability of the
Partnership to continue operations and meet obligations. Based on the
Managing General Partner's evaluation and assessment to date, it is
believed that any interruption in operation will be minor and short-lived
and pose no material monetary loss, safety, or environmental risk to the
Partnership. However, due to the external nature of the potential
problems, it is impossible to accurately identify the risks, quantify
potential impacts or establish a final contingency plan. The Managing
General Partner believes that its assessment and contingency planning will
be complete no later than year-end 1999.
Worst Case Scenario
The Securities and Exchange Commission requires public companies to
forecast the most reasonably likely worst case Year 2000 scenario, assuming
that the Managing General Partner's Year 2000 plan is not effective.
Analysis of the most reasonably likely worst case Year 2000 scenarios the
Partnership may face leads to contemplation of the following possibilities
which, though considered highly unlikely, must be included in any
consideration of worst cases: widespread failure of electrical, gas, and
similar supplies by utilities serving the Partnership; widespread
disruption of the services of communications common carriers; similar
disruption to means and modes of transportation for the Partnership and its
employees, contractors, suppliers, and customers; significant disruption to
the Partnership's ability to gain access to, and continue working in,
office buildings and other facilities; and the failure, of third-parties
systems, the effects of which would have a cumulative material adverse
impact on the Partnership's critical systems. The Partnership could
experience an inability by customers, traders, and others to pay, on a
timely basis or at all, obligations owed to the Partnership. Under these
circumstances, the adverse effect on the Partnership, and the diminution of
Partnership revenues, could be material, although not quantifiable at this
time.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
None
Item 2. Changes in Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matter to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a)Exhibits:
27 Financial Data Schedule
(b) No reports on Form 8-K were filed during the quarter for
which this report is filed.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Southwest Royalties Institutional
Income Fund XI-A, L.P.
a Delaware limited partnership
By: Southwest Royalties, Inc.
Managing General Partner
By: /s/ Bill E. Coggin
------------------------------
Bill E. Coggin, Vice President
and Chief Financial Officer
Date: November 15, 1999